1. Field of the Invention
The present invention is broadly concerned with oil-soluble sulfide-scavenging compositions operable for reducing or essentially eliminating H2S and other objectionable sulfides from hydrocarbon streams or transmission lines and equipment for such products. More particularly, the invention is concerned with such compositions, methods of sulfide-scavenging using the compositions, and methods of preparing the compositions, wherein the compositions comprise respective quantities of triazine and glycol ether, with a minor amount of water up to a maximum of about 15% by volume. The relatively low moisture contents of the compositions, together with the oil solubility thereof, permit scavenging operations in pipelines or equipment with a significant reduction or elimination of corrosion problems experienced with conventional aqueous triazine scavengers.
2. Description of the Prior Art
Natural gas is a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth's surface, often in association with petroleum. As obtained from oil and gas wells, raw or sour natural gas contains a number of impurities which must be removed before being introduced into a pipeline. The principal impurities in natural gas are water, carbon dioxide, hydrogen sulfide and condensable hydrocarbons, such as propane, butane and pentane. These undesirable components are conventionally removed from raw natural gas streams in gas processing plants. The processing plants are normally located in the field and vary in size from small units to large, centrally located plants.
The composition of raw natural gas varies widely from field to field. For example, the methane content can vary between 45 percent and 96 percent by volume, while the hydrogen sulfide content may range from 0.1 ppm to 150,000 ppm. Since hydrogen sulfide is corrosive in the presence of water and poisonous in very small concentrations, it must be almost completely removed from natural gas streams before use and preferably before transport. As a result, many pipeline specifications limit the amount of hydrogen sulfide to less than 0.25 gr per 100 cu. ft. of gas.
The technology known in the art for removing hydrogen sulfide from raw natural gas was developed for large processing plants to remove hydrogen sulfide in continuous processes. These large processing plants are fed by one or more natural gas wells, each of which produces over 10 million cubic feet of natural gas per day. Many of these processes utilize commodity chemicals or proprietary materials to lower the hydrogen sulfide levels in natural gas to pipeline specifications. Also, many of these processes not only sweeten sour natural gas to pipeline specifications, but also regenerate most, if not all, of the sweetening compositions involved.
Generally, there are several methods for sweetening sour gas, i.e., for reducing the hydrogen sulfide content of new gas. For example, various chemicals may be added or injected “in-line” to natural gas pipelines. For example, these sweetening products may be injected at the well head, separators, glycol units, coolers, compressors, etc., to provide contact with the natural gas.
Materials used with such “in-line” injection systems include, e.g., various aldehydes. The hydrogen sulfide reacts rapidly with the aldehyde compounds producing various types of addition products, such as polyethylene sulfide, polymethylene disulfide and trithiane. Such a process is disclosed, e.g., in Walker, J. F., Formaldehyde, Rheinhold Publishing Company, New York, page 66 (1953).
U.S. Pat. No. 4,748,011 discloses a method for the separation and collection of natural gas comprising the use of a sweetening solution. The sweetening solution consists of an aldehyde, a ketone, methanol, an amine inhibitor, sodium or potassium hydroxides and isopropanol. The amine inhibitor includes alkanolamines to adjust the pH.
Although the aldehydes (e.g., formaldehyde) are effective in the reduction of the hydrogen sulfide level of natural gas and selective for sulfide compounds, they are known to form trithiane compounds upon reaction with the sulfides. The trithianes are solids which do not easily dissolve and therefore, clog gas lines.
Also, aldehydes are unstable, temperature sensitive and have the tendency to polymerize. Moreover, aldehydes are known carcinogens and environmental hazards. Accordingly, the use of aldehydes for sweetening natural gas has come under disfavor.
Alkanolamines may also be used to sweeten sour gas streams, e.g., in such “in-line” injection systems. Various alkanolamines may be used in such systems, e.g., monoethanolamine, diethanolamine, methyldiethanolamine and diglycolamine. For example, U.S. Pat. No. 2,776,870 discloses a process for separating acid components from a gas mixture comprising adding to the gas an absorbent containing water-soluble alphatic amines an alkanolamines, preferably ethanolamine.
However, the alkanolamines are not selective in their reaction with hydrogen sulfide. That is, alkanolamines absorb the total acid-gas components present in the gas stream, e.g., carbon dioxide, as well as H2S. Such non-selectivity is not desirable in many applications and therefore, the usage of alkanolamines has also come under disfavor for this reason.
Another method used for the reduction of the hydrogen sulfide level in gas streams is the use of an H2S scrubber tower which causes the gas to contact a sweetening medium. The scrubber/bubble tower processes are batch or one-step processes which increase the opportunity for contact between the natural gas and the sweetening product by providing a gas diffusion zone by way of, e.g., disparges, pall rings, wood chips, etc.
Sweetening materials used in such scrubber tower apparatuses include, e.g., the so-called “iron-sponges.” The iron-sponge is actually a sensitive, hydrated iron oxide supported on wood chips or shavings. The iron oxide selectively reacts with the hydrogen sulfide in the gas to form iron sulfide. Although effective, the iron-sponge method is disadvantageous in that the final product is not easily disposed of (see, e.g., The Field Handling of Natural Gas, p 74, 3rd Ed (1972)).
Slurries of zinc oxide and iron oxides have also been used in such scrubber towers to effect sweetening in much the same way as the iron-sponge. However, disposal problems also exist with these slurries.
Caustic-based systems, such as those containing nitrites, may also be used in scrubber towers. Although effective, such systems produce elemental sulfur solids. Such systems are described in U.S. Pat. No. 4,515,759. Such caustic-based sweetening materials are undesirable since, as noted above, they produce solids (i.e., elemental sulfur). Accordingly, such systems cannot be used in “in-line” injection systems and may only be used in bubble towers. Moreover, such caustic-based sweetening systems are not regenerable, i.e., they must be used in a batch process.
Another known method for sweetening natural gas is the chemical solvent process. The chemical solvent process is a continuous process, whereby a sweetening solution is contacted with the gas stream in an absorber tower. In such a process, the total acid gases, including hydrogen sulfide and carbon dioxide are stripped off of the sweetening solution which is then regenerated. The chemical solvent processes cannot be performed in-line.
Alkanolamines of various types may also be used in these chemical solvent processes. However, as discussed above, the use of alkanolamines is limited due to their lack of selectivity for hydrogen sulfide and other organic sulfides in the gas streams.
Other chemical solvents known in the art and used for sweetening gas streams include piperazinone, as disclosed in U.S. Pat. No. 4,112,049; 1-formylpiperidine, as disclosed in U.S. Pat. No. 4,107,270; iron (III) complexes of N-(2-hydroxyethyl) EDTA, as disclosed in U.S. Pat. No. 4,107,270; and iron complexes of nitriloacetic acid, as disclosed in U.S. Pat. Nos. 4,436,713 and 4,443,423.
U.S. Pat. Nos. 4,978,512 and 7,438,877 describe triazine-based sweetening compositions which preferably utilize the reaction products of a reaction between an alkanolamine and an aldehyde as the triazine source. Generally, these triazine products have from 40-70% by volume water therein. This is a problem when the compositions are used as a part of in-line systems or spray systems to scavenge sulfides from petroleum transmission lines and equipment. Specifically, the high moisture contents of the compositions significantly contribute to corrosion of the transmission lines and equipment. In short, while adequate sulfide scavenging can be obtained, this can be largely offset by the concomitant issue of corrosion.
The following references describe further compositions and methods of scavenging.
U.S. Pat. No.Inventor(s)4,044,100McElroy5,462,721Pounds et al.5,589,149Garland et al.5,733,516DeBerry5,738,834Deberry6,267,938Warrender et al.6,818,194DeBerry et al.7,078,005Smith et al.Published Patent ApplicationInventor(s)2009/0263302HuForeign PublicationsInventor(s)WO9301126GatlinRU2118649Magsumovic et al.GB1325913Payne et al.Non-Patent LiteratureRinaldi. Acid Gas Absorption by Means of Aqueous Solutions ofRegenerable Phenol-Modified Polyalkylenepolyamine Ind. Eng. Chem. Res.1997, 36, pp. 3778-3782.